Most petroleum deposits contain constituents that would be solids or near-solids at ordinary room temperatures. For many lighter grades of petroleum, these constituents are primarily paraffins. In other deposits, these fractions may be mostly asphalts. For either type of petroleum, these constituents tend to condense from the fluid flow as it moves upwardly in a well through the usual production tubing. That is, the heavier fractions tend to precipitate as the fluid cools on its way toward the surface, moving into increasingly cooler regions; these fractions tend to accumulate in the production tubing and limit the production rate. Accumulations of paraffin in and on the production tubing may stop flow entirely. Similar problems are encountered in wells producing heavy crudes that become highly viscous as the fluid cools in its movement toward the surface.
The term "condensible constituents", as used herein, includes paraffins, asphalts, and any other constituents that tend to coagulate, condense, precipitate, or otherwise accumulate in the cooler portions of a mineral well. Action must frequently be taken to clear accumulations of such condensible constituents and restore the well to normal operation. Similar problems occur in other mineral wells having a substantial sulphur content in the fluids produced.
Paraffin precipitation problems may be quite severe in shallow wells with producing formation (reservoir) temperatures that are only slightly above the temperatures at which accumulations of condensible constituents occur. The expansion in the volume of fluids that occurs during petroleum production cools the fluids sufficiently to cause condensation. Such condensation causes plugging of the perforations in the well casing and of pore spaces in the reservoir, in addition to accumulating in the tubing as described above. Action must frequently be taken to remove the accumulated paraffin. Similar problems also occur with deep sour gas wells in which accumulation of sulfur in the reservoir and/or tubing causes rapid decline in the fluid production rate. Accumulation of sulfur in such wells is believed to be due to changes in both the physical state and chemical composition of the fluid as it cools during expansion in the wellbore region or as it moves upwardly through the production tubing. Thus, in such wells sulphur is a "condensible constituent".
In gas wells, mixtures of hydrocarbons and water vapor, upon a change in pressure or a decrease in temperature, may form hydrate crystals which can block the flow of the desired fluids. Other gas wells produce small amounts of heavy, viscous oils which condense in the cooler zones and tend to decrease production. Expansion of gases, evaporation of volatiles and decrease in temperature near the earth surface are largely responsible for the condensation/accumulation phenomena occurring in these wells. Again, such accumulations constitute "condensible constituents" from the fluids produced by the wells.
A variety of techniques have been proposed to mitigate, eliminate, or correct the effects of precipitation of paraffins or the accumulation of other condensible constituents within the production tubing of oil wells, gas wells, and other mineral wells. Thus, a variety of knives and scrapers have been tried for mechanical removal of accumulations from the production tubing. These scrapers are sometimes attached to the pump rods of the wells; in other instances, it is necessary to remove the pump rod to permit insertion of the scrapers to cut loose accumulated deposits of paraffin, asphalt, or the like. In some proposals, a solvent or diluent is utilized to loosen the paraffin or other condensible constituents from the interior of the production tubing so that they can be pumped to the surface. Solvents are also sometimes injected into the producing formation (reservoir) to dissolve paraffin accumulated in the casing perforations and reservoir pore spaces. In viscous oil wells, diluents are often added to reduce pumping difficulties. In most of these systems, the well must be shut down, adding to the expense of reworking the well to clean out deposits within the production tubing.
Electrical heating systems have also been proposed as a cure for condensation of paraffin, asphalt and other condensible constituents in mineral wells such as oil wells, gas wells, and the like. In some of these systems, a discrete electrical heater is positioned downhole in the well, frequently at or near the level of the deposit from which mineral fluid is being drawn, and is energized from an electrical cable. Such discrete heaters, while useful, only heat a portion of the tubing and rely on the flow of crude to heat the remainder of the tubing. Except for quite high flow rates, this effectively heats only about thirty to fifty meters of tubing above the heater. Also, cable life within a mineral well tends to be quite short and frequent replacement of the cable, at substantial expense, becomes a necessity. Keeping the heating equipment in operation is also quite difficult; burnouts are relatively frequent.
Other proposed systems are directed to the removal of paraffin deposits after condensation, with the production tubing and well casing utilized as active components in a heating system. An early example of a system of this kind is described in Looman U.S. Pat. No. 2,244,255 for "Well Clearing System". In that system a motor generator or specially built transformer has one lead connected to the production tubing and the other to the well casing. The casing and tubing are insulated from each other except in a lower part of the well, where a sliding electrical contact is established between the tubing and the casing to define a lower limit for a heating zone. The overall system requires high currents and high power dissipation; the only example requires a current of 750 amperes and a power (heat) dissipation rate of 37.5 kilowatts. The system is energized periodically to melt the paraffin accumulations within the production tubing and is then turned off to permit normal operation of the well.
A similar system is described in Green U.S. Pat. No. 2,982,354 for "Paraffin Removing Device", which utilizes a timing control or an energization control responsive to the output of a strain gauge connected to the pump rod. Green's system periodically supplies a large surge of power to melt the paraffin. Yet another similar system is disclosed in Marr U.S. Pat. No. 4,319,632 for "Oil Recovery Well Paraffin Elimination Means". The objective of the Marr arrangement is to heat the casing above the melting point of the paraffin. The heating current flows primarily through an insulated cable attached to the well casing. This causes much of the heat to be dissipated in the casing and lost to surrounding ground formations. The Marr arrangement has the further disadvantage that its power cable is subject to the service difficulties noted above.
A rather different technique for attacking the paraffin condensation problem is described in Gill U.S. Pat. No. 3,614,986 for "Method of Injecting Heated Fluids into Mineral Bearing Formations". In that system a hot liquid (oil) is periodically pumped into the well to melt or dissolve any accumulations of paraffin or other condensible constituents, after which the well is restored to operation. To keep the heat loss in a deep well from defeating the purpose of the hot oil injection, the Gill system provides an electrical heating arrangement like those described in the Looman and Green patents, but only for the purpose of compensating for heat losses experienced by the downwardly flowing heated liquids. As in the other systems discussed above, the Gill arrangement is intended to melt or dissolve the paraffin or other condensate accumulations with the well shut down (for the injection of hot fluids), following which normal operation is restored until a subsequent clean-out is required.
In another known method a heating tape is attached to the production tubing. This technique can achieve heating in a short period of time, but the system is inconvenient to install and, if rework is required, the heating tape must be detached from the tubing and collected on a separate reel. A special well-top header is required to allow a multi-conductor electrical power cable to pass through the header for connection to the heating tape within the annulus between the tubing and the casing. Long term deterioration of the cabling in the hostile environment of a downhole system can be anticipated from both the chemical constituents of the fluids and mechanical movements of the tubing. The downhole tubing expands and contracts not only with temperature but also with the forces associated with pumping. Such forces can cause the tubing to rub against the wall of the casing, which can cause rapid deterioration of the heating tape. Manufacturers of such tape systems recommend that the tubing system be held at temperatures about 10.degree. to 20.degree. F. (5.degree. to 10.degree. C.) above the pour point of the oil. For many high-gravity paraffin prone oils, holding the tubing temperature no more than 20.degree. F. above the pour point could result in substantial paraffin precipitation.